Field of the Invention
Embodiments of the present invention generally relate to methods and apparatus for analyzing measurements taken in a wellbore, or more generally in an area or oilfield with potential hydrocarbons. In particular, embodiments of the present invention relate to methods and apparatus for three/four dimensional data management and imaging of big oilfield measurement data.
Description of the Related Art
Oilfield measurements, including geophone data (seismic) and airborne surveys such as microseep data, can help in characterizing the subsurface with geological mapping and hydrocarbon detection. The data gathered from these techniques can be significantly large, and accurate visualization of data without data reduction may be required to identify detailed subsurface geometries. The subsurface is also constantly changing as a result of production or operation activities such as steam injection (e.g., steam assisted gravity drainage—SAGD). In these situations, 4D seismic measurements may need to be gathered and mapped to understand the subsurface/reservoir changes.
In addition to the oilfield measurements discussed above, various reservoir monitoring systems have been used to measure important properties such as pressure, temperature, acoustic, strain, and Bragg gradient along the wellbore. Formation properties at downhole subsurface conditions, like porosity, permeability, density, mineral content, electrical conductivity, and bed thickness, and computed fluid properties such as viscosity, chemical elements, and the content of oil, water, and/or gas are essential. Monitoring such properties and conditions, either instantaneously or by determining trends over time, may have significant value in understanding fluid flow through different fluid entries in the producing zones. Examples of reservoir monitoring include utilizing distributed temperature sensing (DTS) or distributed acoustic sensing (DAS) along a length of a wellbore, such that the monitoring is performed with the functional equivalent of tens, hundreds, or thousands of sensors. In other words, a fiber optic cable may function as a continuous sensor. An example of a DAS system will be further described.
FIG. 1 illustrates a schematic cross-sectional view of a wellbore 102, wherein a DAS system 110 may be used to perform acoustic sensing. A DAS system may be capable of producing the functional equivalent of tens, hundreds, or even thousands of acoustic sensors. Properties of the wellbore 102, a wellbore completion (e.g., casing, cement, production tubing, packers), and/or downhole formations and interstitial fluid properties surrounding or otherwise adjacent the wellbore 102 may be monitored over time based on the acoustic sensing. Further, hydrocarbon production may be controlled, or reservoirs 108 may be managed, based on these monitored properties.
The wellbore 102 may have a casing 104 disposed within, through which production tubing 106 may be deployed as part of a wellbore completion. The DAS system 110 may comprise an acoustic energy source and a DAS device. An active acoustic energy source may generate and emit acoustic signals downhole. For some embodiments, an active acoustic energy source may not be involved in situations where acoustic signals are generated passively (e.g., seismic or microseismic activity). The acoustic signals may interact with the wellbore 102, the wellbore completion, and/or various downhole formations or fluids adjacent the wellbore, leading to transmitted, reflected, refracted, absorbed, and/or dispersed acoustic signals. Measured acoustic signals may have various amplitude, frequency, and phase properties affected by the downhole environment, which may stay constant or change over time. Useful instantaneous, relative changes, time lapse, or accumulated data may be derived from the DAS system 110.
An optical waveguide, such as an optical fiber, within the wellbore 102 may function as the DAS device, measuring disturbances in scattered light that may be propagated within the waveguide (e.g., within the core of an optical fiber). The disturbances in the scattered light may be due to the transmitted, reflected, and/or refracted acoustic signals, wherein these acoustic signals may change the index of refraction of the waveguide or mechanically deform the waveguide such that the optical propagation time or distance, respectively, changes.
The DAS device generally includes employing a single fiber or multiple fibers in the same well and/or multiple wells. For example, multiple fibers may be utilized in different sections of a well, so that acoustic sensing may be performed in the different sections. Sensing may occur at relative levels or stations, immediately adjacent depth levels, or spatially remote depths. The DAS device may involve continuous or periodic dense coiling around a conduit to enhance detection, and coiling the fiber in various physical forms or directions may enhance dimensional fidelity.
The system 110 may have various effective measurement spatial resolutions along the DAS device, depending on the selected pulse widths and optical power of the laser or light source, as well as the acoustic source signature. Therefore, the DAS device may be capable of producing the functional equivalent of tens, hundreds, or even thousands of acoustic sensors along the waveguide, wherein acoustic sensors and/or their functional DAS equivalents may be used for the DAS system 110 in addition to the acoustic source.
Oilfield and wellbore data measurements, such as those previously discussed, are rapidly growing, especially in sensors such as distributed temperature, pressure, acoustic, strain, and chemical sensing. The datasets from sensing are typically obtained at high frequency and time intervals, and the generated data can be in the terabytes. Traditional techniques are inadequate for analyzing such large volumes of data, and most techniques decimate the data. As a result, the original resolution of the data can be lost and specific events particular times may not be analyzed and may instead be lost in the decimation or downsampling.